Method and System for Monitoring The Incursion of Particulate Material into A Well Casing within Hydrocarbon Bearing Formations including Gas Hydrates

ABSTRACT

A method and system for monitoring any incursion of particulate matter from a gas hydrate formation into a well casing used for the production of the gas hydrate and determining the degree of incursion of particulate material within the distal end of the well casing.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a divisional application of U.S. patent applicationSer. No. 13/018325, filed Jan. 31, 2011, which is a division divisionalof U.S. patent application Ser. No. 11/612,494, filed Dec. 19, 2006,which claims the benefit under 35 U.S.C. §119(e) of applicants' U.S.Provisional Application Ser. No. 60/752,118 entitled “Systems and Methodfor Development of Hydrocarbon Bearing Formations,” filed Dec. 20, 2005,the entire disclosure of this Provisional Application is herebyincorporated by reference as though set forth at length.

BACKGROUND

This invention is generally related to a method and system formonitoring the incursion of particulate matter into a well casing thatis designed for recovering hydrocarbons from subterranean formations. Inone useful aspect this invention relates to a method and system fordetecting and measuring the buildup or accumulation of sand within awell casing operable for producing methane gas from gas hydrateformations

A gas hydrate is a crystalline solid that is a cage-like lattice of amechanical intermingling of gas molecules in combination with moleculesof water. The name for the parent class of compounds is “clathrates”which comes from the Latin word meaning “to enclose with bars.” Thestructure is similar to ice but exists at temperatures well above thefreezing point of ice. Gas hydrates include carbon dioxide, hydrogensulfide, and several low carbon number hydrocarbons, including methane.One aspect of this invention is the recovery of methane fromsubterranean methane hydrates.

Methane hydrates are known to exist in large quantities in two types ofgeologic formations: (1) in permafrost regions where cold temperaturesexist in shallow sediments and (2) beneath the ocean floor at waterdepths greater than 500 meters where high pressures prevail. Largedeposits of methane hydrates have been located in the United States inAlaska, the west coast from California to Washington, the east coast inwater depths of 800 meters, and in the Gulf of Mexico (other well knownareas include, Japan, Canada and Russia).

A U.S. Geological Survey study estimates that in-place gas resourceswithin gas hydrates consist of about 200,000 trillion cubic feet whichdwarfs the previously estimated 1,400 trillion cubic feet ofconventional recoverable gas reserves in the United States. Worldwide,estimates of the natural gas potential of gas hydrates approach 400million trillion cubic feet.

Natural gas is an important energy source in the United States. It isestimated that by 2025 natural gas consumption in the United States willbe nearly 31 trillion cubic feet. Given the importance and demand fornatural gas the development of new cost-effective sources can be asignificant benefit for American consumers.

Notwithstanding the obvious advantages and potential of methanehydrates, production of methane from gas hydrates is a challenge for theindustry. When trying to extract methane from a gas hydrate thesequestered gas molecules must first be dissociated, in situ, from thehydrate. There are typically three methods known that can be used tocreate this dissociation.

One method is to heat the gas hydrate formation to liberate the methanemolecules. This method is disclosed in United States Patent ApplicationPublication No. US 2006/0032637 entitled “Method for Exploitation of GasHydrates” published on Feb. 16, 2006, and of common assignment with thesubject application. The disclosure of this publication is incorporatedherein by reference as background information with respect to thesubject invention.

Another method envisioned for producing methane hydrates is to injectchemicals into the hydrate formation to change the phase behavior of theformation.

A third technique, which is one aspect of the instant invention, isregarded as a depressurization method. This method involvesdepressurization of a gas hydrate formation and maintaining a relativelyconstant depressurization on the hydrate formation to allow dissociationand then withdrawing dissociated gas and water through a well casing.

In all of the above mentioned techniques a well casing is used to bringgas and fluids to the surface for separation and processing. Sanding atthe distal end of the well casing in methane hydrate production, as wellas in conventional oil and gas recovery, will often cause a criticalproblem. In this, sand can damage completion equipment and in a worstcase scenario stop production. Therefore it would be highly desirable toprovide a method and system which would be capable of estimating themovement of the sand-fluid interface position within the well casing.

SUMMARY OF THE DISCLOSURE

There are four concepts envisioned in the subject disclosure foraddressing sanding within a production casing.

One envisioned method and system comprises installation of two pressuresensors, below a submergible pump at the bottom or distal end of a wellcasing. By measuring the pressure noise variance between the twopressure sensors, such as phase shift or amplitude change, the height ofsand entrapped within a well casing can be estimated.

Another method and system utilizes a continuous thermal characteristicsmeasurement device, such as a distributed temperature sensing system(Hot-DTS). This unit may be installed, for example, below the completionstring. By measuring the temperature or thermal characteristics of thesurrounding material with the temperature sensing device the position ofthe sand-fluid interface may be estimated.

Further, an acoustic transmitter and receiver may be installed at, forexample, the bottom of the completion string. By observing the waveformof the sound generated and received, the distance between thetransmitter/receiver and the sand-fluid interface may be estimated.

Still further a vibrator and vibrating bar may be installed, forexample, below the completion string. By observing the vibration mode ofthe bar, the position of the sand-fluid interface may be estimated.

THE DRAWINGS

Other features and aspects of the disclosure will become apparent fromthe following detailed description of some embodiments taken inconjunction with the accompanying drawings wherein:

FIG. 1 is a pictorial view of one context or geological region ofpermafrost in Alaska where gas hydrates are know to exist;

FIG. 2 is a pictorial view of another context or geological region ofgas hydrates beneath offshore regions of the United States in watergreater than 500 meters;

FIG. 3 is a schematic representation of one technique for producing amethane hydrate that includes a depressurization production systemincluding maintaining a desired level of pressure within a wellincluding returning water into the well from a surface valve system;

FIG. 4 is a schematic representation of one embodiment of the inventionthat includes two pressure sensors and the use of pressure noisevariance between the two sensors to estimate the height of sand withinthe distal end of a well casing;

FIG. 5 is a schematic representation of another embodiment of theinvention that discloses a distributed temperature sensing system forestimating the sand-fluid interface within a well casing;

FIG. 6 is a schematic representation of yet another embodiment of theinvention that includes an acoustic transmitter and receiver pair at thebottom of a completion string; and

FIG. 7 is yet another embodiment and discloses a vibrator and vibratingbar installed below the completion string.

DETAILED DESCRIPTION

Turning now to the drawings wherein like numerals indicate like parts,FIG. 1 discloses a pictorial representation of one operating context ofthe invention. In this view a band of gas hydrate 10 lies in a rathershallow geologic zone beneath a permafrost layer 12 such as exists inAlaska. Other earth formations 14 and/or aquifer regions 16 can existbeneath the gas hydrate.

In order to recover sequestered methane gas from within the gas hydratezone one or more wells 18, 20 and/or 22 are drilled through thepermafrost 12 and into the gas hydrate zone 10. Usually a casing iscemented within the well and one or more windows are opened directlyinto the hydrate zone to depressurize irregular regions of the gashydrate represented by irregular production zones 24, 26, 28 and 30extending away from distal terminals of the wells. Although a singlewell is shown drilled from a single derrick illustrated at 18 and 22 itis envisioned that directional drilling as illustrated at derrick 20 andzone 30 will be a more common practice to extend the scope of a drillingoperation.

Once one or more wells are drilled, pressure is relieved from the gashydrate zone around the well and the methane gas and water moleculeswill separate and enter the wells. The gas can then be separated fromthe water and allowed to rise to the surface or is pumped to the surfacealong with water and separated and fed along a pipeline 32 to acompressor station not shown.

An alternative operating context of the invention is illustrated in FIG.2 where a drillship 40 is shown floating upon the surface 42 of a bodyof water 44 such the Gulf of Mexico. In this marine environment,pressures in water depths approximately greater that 500 meters havebeen conducive to the formation again of geologic layers of gas hydrates46, such as methane hydrates, beneath the seabed 48.

Offshore drilling in water depths of 500 meters or more is nowtechnically possible so that drilling into the offshore gas hydrateformations 46 and cementing a casing into a well hole offshore to form aproduction strata 50 is another source of production of methane from agas hydrate formation. Again, directional drilling from a subseatemplate enables fifty or more wells to be drilled from a singledrillship location.

Turning now to FIG. 3, there will be seen one method and system inaccordance with one embodiment of the invention. In this, a well hole 60is drilled through an earth formation 62 and into a previouslyidentified geologic layer of methane hydrate 64. A casing 66 ispositioned within the well and cemented around the outer annulus forproduction. At a selected depth, which may be relatively shallow fordrilling through permafrost or deep if offshore, the casing isperforated by one or more windows 68 which establish open communicationbetween the interior of the well casing and a zone of methane hydrateunder pressure. This opening of the well casing will relieve pressure onthe surrounding methane hydrate and will enable previously sequesteredmethane gas to dissociate from the lattice structure of water moleculesto form a physical mixture of gas and water. The gas and water 70 willthen flow into the well casing 66 and rise to a level 72 within thecasing consistent with a desired level of pressure within the wellcasing. In other words, the submersible pump pumps water out of the wellcreating a lower hydrostatic pressure on the hydrate to dissociate. Oncethe hydrate dissociates, the water and gas will flow into the wellboreraising the water level which lowers the drawdown pressure which thentends to prevent further dissociation. This is a self limiting processthus the submersible pump is used to pump out the water within the wellcasing to lower the water level and to maintain the drawdown pressurenecessary for continuous dissociation. The pump creates the drawdownpressure. An automated feedback loop maintains a constant drawdownpressure by re-circulating some amount of produced water.

In order to recover methane gas from the mixture, the gas and watermixture is pumped to the surface by an electro submersible pump (ESP) 74connected to the distal end of a first conduit 76 extending into thewell casing 66.

Some downhole pumps require a minimum amount of flow rate to stabilizepump performance, such as an ESP. Some hydrocarbon reservoirs do nothave enough production flow, such as in methane hydrate productionwells, to efficiently use a full production ESP. Methane hydrateproduction flow depends on not only formation permeability, but also onthe rate or volume of hydrate dissociation. Accordingly, production ratemay change from time to time which may require the pump size to bechanged. The present invention endeavors to provide methods and systemsthat generate the minimum flow rate of fluids for the pump by a flowback loop that may be used to return pumped out fluid back into the wellcasing to be recycled. In this, it is possible to handle a wide range ofproduction rates with only one large capacity downhole pump.

At the surface the gas and water mixture passes through a conventionalgas and water separator 78 where methane gas is separated, monitored anddelivered to a pipe 80 for collection by a compressor unit. Downstreamof the separator/monitor 78 is a valve 82 to control the flow of waterout of the system. Prior to reaching valve 82 a branch or second conduit84 is joined into the first conduit and extends back into the wellcasing 66. This enables water from the well that has been separated fromthe mixture at 78 to be reintroduced back into the well casing tomaintain at least a minimum level of water 72 within the well casing forefficient operation of the ESP 74.

Control of the volume of water reintroduced into the well casing isprovided by a choke valve 86 that is positioned within the secondconduit 84 as illustrated in FIG. 3. The position of the choke valve canbe regulated by a control line running from the intake of the ESP to thechoke valve 86. This enables the system to maintain a constant pressurewithin the well casing 66 by controlling the volume of waterreintroduced into the system.

Depending upon the pressure within the well casing there may be atendency for the gas and water mixture to solidify within the wellcasing 66, ESP 74 or first conduit 76. The temperature of waterreturning to the well casing can be regulated by a temperature controlunit 90 connected to the return water or second conduit 84 to minimizethis issue.

In addition to collecting methane gas from the separator 78 methane gasis drawn directly from the top of the well casing by a third conduit 92that passes through a gas production monitor 94 which also delivers gasto a compressor storage system.

Depending on the downhole well casing pressure and the pressure withinthe ESP 74 the gas and water mixture 70 may tend to re-solidify during apumping operation within the ESP intake (thus upstream of the ESP),within the ESP 74 itself or downstream of the ESP within the firstconduit 76. In order to minimize this tendency a fourth conduit 96 isextended within the casing 66 and is operable to feed a chemical, suchas methanol, upstream of the ESP 74, directly into the ESP or downstreamof the ESP to minimize reformation of methane hydrate within the system.

In producing methane from a gas hydrate, or other hydrocarbon productionsuch as conventional natural gas or oil reserves, the productionhydrocarbon flows from a subterranean formation and into a productionwell casing to be pumped to the surface for processing.

In such operations particulate material such as sand entrained withinhydrocarbon fluid streams can enter access windows in the well casingalong with the hydrocarbon for production and settle to the bottom ofthe well casing. As the volume of sand collects within the casing,efficiency of the production may be compromised, and, accordingly sandmanagement within a production program is at least desirable andsometimes critical to efficient production.

One embodiment of the disclosure for monitoring sand build-up isdisclosed in FIG. 4. In this embodiment a well casing 100 is showncemented within a well drilled into a gas hydrate production zone 102.The casing is fashioned with production windows 104 that are cut orblown through the side wall of the casing to permit ambienthydrocarbons, such as for example dissociated methane gas and water, toenter the well casing.

Sometimes entrained with incoming pressurized hydrocarbons and water isparticulate matter such as sand 106. This relatively heavy sand tends tofall by gravity into a lowest portion of the well casing as illustratedin FIG. 4. Depending on the volume of sand that accumulates thesand-fluid interface 108 may reach the level of the well casing windows104 and at least partially occlude the window openings and thus impairthe efficiency of the hydrocarbon recovery.

Although techniques are know to prevent sand from entering the wellcasing system, over time particulate material can accumulate within thecasing. In certain instances it has been desirable to allow sand toenter the casing to enable the sanding tendency in new formations.However, since there is production equipment that can be damaged bysand, as well as decreasing well efficiency, sand production needs to bedetected and the level of sand accumulation determined to enable anoperator to take preemptive management before the level of sand becomesproblematic.

In the FIG. 4 embodiment, a first pressure sensor 110 is positioned atthe bottom of a submersible pump 112 and a second pressure sensor orgauge 114 is positioned near the distal end of the well casing.Accordingly, downhole pressure at the submerged pump level and at nearthe distal end of the well casing is monitored.

In this pressure variance monitoring system of FIG. 4, a ripple, i.e.,noise, is generated in the pressure readings. If the pressure reading isstable, the motor speed of the pump 112 is controlled to generate noisein the pressure reading. The sand layer 106 may be considered as apressure filter, and the pressure response at the bottom sensor 114 is afunction of the sand column height Ha when the well casing is vertical.Alternatively, for lateral drilling operations the accumulation of sandand a fluid-sand interface can be at an angle with respect to a verticalorientation The sand column accumulation Ha may be estimated byanalyzing the noise waveform variation, such as phase shift or amplitudevariation.

Turning now to FIG. 5, a second embodiment of the disclosure isdisclosed. In this embodiment, a well casing 120 is shown cemented intoa borehole drilled into a hydrocarbon production zone such as a gashydrate 122. Production windows 124 are cut into the casing to allow theflow of hydrocarbons into the well casing for recovery. As noted abovesand 126 can also enter the well casing and collect by gravity at alowermost location of the casing 120.

In this embodiment a continuous thermal characteristic measurementdevice 128, such as a distributed temperature sensing system (Hot-DTS),is installed, for example, below the completion string. The DTS is afiber optic temperature sensor that is run within tubing 130 from thesubmersible pump 132 to a distal end of the well casing 120. Bymeasuring the temperature or thermal characteristics, for example,thermal conductivity, of the surrounding material with the temperaturesensing device 128 the position of the sand-fluid interface may beestimated. Methods and systems for distributed temperature sensing aredisclosed in U.S. patent application Ser. No. 11/346,926 entitled“Systems and Methods of Downhole Thermal Property Measurement”, filed onFeb. 3, 2006, and of common assignment with the subject application. Thedisclosure of this application is incorporated herein by reference inits entirety.

The tubing or cable 130 can have a built in heater section which can beturned on to create a more dramatic thermal conductivity difference atthe sand-fluid interface Hb.

Another embodiment of the disclosure is depicted in FIG. 6. Here a wellcasing 140 is again shown cemented within a hydrocarbon production zone142. In this embodiment the sand-fluid interface 144 is determined bythe provision of an acoustic transmitter 146 and a receiver 148connected to the submersible pump 150.

By observing the waveform of sound generated by the transmitter 146 andreceived by the receiver 148, the distance between thetransmitter/receiver and the sand-fluid interface Hc may be estimated.

Turning now to yet another embodiment of the disclosure in FIG. 7 asimilar well casing 160 is shown cemented into a hydrocarbon productionzone 162. In this embodiment a vibrator 164 is connected to the base ofa submersible pump 166 and a vibration bar 168 extends from the vibratorto the distal end of the well casing 166 and into sand 170 that hasaccumulated within the well casing. By observing the vibration mode ofthe bar, the position Hd of the sand-fluid interface below the vibrator164 is estimated. In this, the vibrating bar response system is based onthe damping factor of sand being higher than that of water. As shown inFIG. 7, the vibration mode of the bar 168 will vary with the depthchange of the sand-fluid interface. Therefore, by observing thevibration mode of the bar, the fluid-sand ratio may be determined, whichwould indicate fluid/sand height.

In each of the above discussed embodiments a novel technique is utilizedto monitor the level of sand within a well casing so the remedial actionmay be initiated as necessary or desirable.

In describing the invention, reference has been made to some embodimentsand illustrative advantages of the disclosure. Those skilled in the art,however, and familiar with the subject disclosure may recognizeadditions, deletions, modifications, substitutions and other changeswhich fall within the purview of the subject claims.

What is claimed is:
 1. A system for determining the degree of incursionof particulate matter into a well casing used in the production of gasfrom a subterranean gas hydrate formation, said system comprising: avibrator connected beneath a submersible pump positioned within the wellcasing for pumping gas and water out of the well casing; a vibration barconnected to said vibrator and extending toward the distal end of thewell casing, wherein observation of the vibration mode of said vibrationbar enables estimation of the interface between fluid and particulatematerial within the distal end of the well casing.